Methods and systems for monitoring near-wellbore and far-field reservoir properties using formation-embedded pressure sensors

ABSTRACT

A method for measuring formation property includes obtaining a set of measurements indicative of wellbore pressures for a selected duration after a pressure perturbation is created in a wellbore; obtaining at least one additional set of measurements indicative of formation pressures for the selected duration after the pressure perturbation; and deriving the formation property based on the set of measurements indicative of the wellbore pressures and the at least one additional set of measurements indicative of formation pressures. A system for measuring formation property includes a first pressure sensor disposed proximate a wellbore for measuring pressures in the wellbore; a second pressure sensor disposed in a formation at a predetermined distance from the wellbore; and a flow rate measuring device.

BACKGROUND OF INVENTION

1. Field of the Invention

The invention relates generally to methods and systems for monitoring formation properties. More particularly, the invention relates to measuring or monitoring formation properties using sensors disposed in a wellbore and in formations.

2. Background Art

Wells for the production of hydrocarbons such as oil and natural gas should be carefully monitored to prevent catastrophic mishaps that may be dangerous and have severe environmental impacts. In addition, the production of a well should be monitored and controlled to maximize the production over time. Well production levels and efficiencies depend on reservoir formation characteristics (such as pressure, porosity, permeability, temperature and physical layout of the reservoir) and the nature of the hydrocarbon (or other material) extracted from the formation.

Producing hydrocarbons too quickly from a well may result in stranding hydrocarbons in the formation. For example, improper production may separate an oil pool into multiple portions. In such cases, additional wells may need to be drilled to produce the oil from the separated pools. However, legal restrictions or economic considerations may not allow another well to be drilled, thereby stranding the pools of oils and wasting their potentials for revenues.

Real-time monitoring of formation properties may be used to determine the production status and for decision making. For example, in a laminated reservoir having different zones or layers, mapping the formation properties of these zones can help an operator decide whether to run more perforations in selected zones to increase productivity.

Various techniques are available for mapping formation or reservoir properties. For example, U.S. Pat. Nos. 5,548,563 and 5,787,050, issued to Slevinsky, disclose methods for establishing the location and orientation of the reservoir boundaries. These patents are incorporated by reference in their entirety. In accordance with methods disclosed in these patents, conventional pressure test is performed on a well, such as using a formation tester in a wellbore to perform drawdown, shut-in, and buildup tests. The formation's pressure responses, as defined by the rate of pressure changes in the reservoir over time, are measured. From these measurements, conventional techniques may be used to determine the radius of investigation. Then, the calculated (theoretical) response for an infinite and radially extending well and the measured response are compared as a ratio. Variation of the ratio from unity is indicative of the presence of a boundary and its magnitude is related to an angle-of-view, which is related to the orientation of the boundary to the well.

In addition to performing pressure tests from the wellbore, sensors may also be deployed in the formations (typically near wellbore) to monitor the pressure responses. For example, U.S. Pat. No. 7,140,434, issued to Chouzenoux et al. discloses sensors and methods that may be deployed in formation layers to monitor the production of a well. As disclosed in this patent and illustrated in FIG. 1, to monitor pressure development in layered formations, such as layered sands, several pressure-measurement sensors 11 may be placed in a producer well 122 that has been previously drilled and cased. In this example, the sensors are deployed along the wellbore in reservoir section 10. Some sensors are deployed in the perforated zone 124, while others are deployed above and below the perforated zone 124. In low “vertical” permeability formations typically encountered in laminated sands reservoirs, the non-perforated sections above and below the perforated sections are expected to have a low contribution to the production because the flow is mostly radial and the vertical cross-flow is limited.

Having the sensors in the formations, the operator can monitor and/or probe the production characteristics of the zones or the well. For example, by varying the well flow (production) rate Q, the operator may monitor the changes in the pressures as detected by the different sensors in different layers. If the pressure is constant within a layer while the well flow is varied, the particular layer has a low contribution to the overall well production. The pressure transient recording would look like “Pressure Response 1” (inset in FIG. 1). In a layer that substantially contributes to the well production, the pressure response will vary as the well flow is modified. The response will took like “Pressure Response 2”. Therefore, by monitoring the pressure in each layer as a function of the overall production flow, it is possible to characterize the productivity of the particular layer. An operator can then use this information to decide whether to run complementary perforations in order to better produce the whole reservoir section

The prior art methods, whether using sensors in the wellbore or in the formations, typically focus on monitoring a well in the axial direction along the wellbore (i.e., in a vertical direction for a typical vertical well). However, knowing the reservoir characteristics (e.g., porosity, the pressure, and permeability) in the radial direction (from the wellbore into the formations), i.e., within a production zone, is as important. For example, knowing the reservoir boundaries or formation permeabilities along the fluid path to the wellbore within a production zone may help the operator decide how to produce the well to obtain the maximum economic benefits. In addition, mapping the formation properties in the radial directions is critical when injecting fluid (such as water and steam) into a formation through an injection well to drive oil or gas to a production well. By monitoring how the interfaces between different fluids change with time, decisions can be made to stop or reduce production before the injection fluid reaches the production well.

Therefore, there exists a need for methods and systems that can be used to measure or monitor the formation properties in the radial direction, for example, within the same layer at different distances from the wellbore.

SUMMARY OF INVENTION

In one aspect, the present invention relates to methods for measuring formation property. A method in accordance with one embodiment of the invention includes obtaining a set of measurements indicative of wellbore pressures for a selected duration after a pressure perturbation is created in a wellbore; obtaining at least one additional set of measurements indicative of formation pressures for the selected duration after the pressure perturbation; and deriving the formation property based on the set of measurements indicative of the wellbore pressures and the at least one additional set of measurements indicative of formation pressures.

In another aspect, the present invention relates to systems for measuring formation property. A system in accordance with one embodiment of the invention includes a first pressure sensor disposed proximate a wellbore for measuring pressures in the wellbore; a second pressure sensor disposed in a formation at a predetermined distance from the wellbore; and a flow rate measuring device.

Other aspects and advantages of the invention will become apparent from the following description and the attached claims.

BRIEF SUMMARY OF THE DRAWINGS

FIG. 1 shows a conventional system for pressure monitoring in a laminated reservoir.

FIG. 2 shows a system for monitoring formation properties in accordance with one embodiment of the invention.

FIG. 3 shows results from formation property study using a system shown in FIG. 2; the graph shows a near wellbore production index derived from the results.

FIG. 4 shows a system for monitoring formation properties in accordance with another embodiment of the invention.

FIG. 5 shows a system for monitoring formation properties disposed in a formation having two boundaries in accordance with one embodiment of the invention.

FIG. 6 shows Homer and Bourdet curves based on pressure data obtained using the system of FIG. 5.

FIG. 7 shows a flow chart of a method for formation property monitoring in accordance with one embodiment of the invention.

It is to be understood that the drawings are to be used for the purpose of illustration only, and not as a definition of the metes and bounds of the invention, or as a basis for reading non-existent or un-recited limitations into the claims.

DETAILED DESCRIPTION

Embodiments of the invention relate to methods and systems for measuring or monitoring formation properties at different radial distances from the wellbore. For example, near-wellbore and far-field reservoir properties may be determined or monitored using sensors, e.g., pressure sensors, disposed in the wellbore and/or in the formation. In accordance with embodiments of the invention, such measuring or monitoring typically are performed within the same sedimentation layers or zones.

FIG. 2 illustrates a formation property monitoring system in accordance with one embodiment of the invention. As shown in FIG. 2, a wellbore 20 is drilled in the formations 10. The wellbore 20 penetrates a production zone 10 a. In order to monitor the properties of the zone 10 a, a sensor 21 is deployed in the wellbore 20 and another sensor 22 is disposed in the formation (e.g., in the production zone 10 a). While the sensor 21 is shown to be disposed in the wellbore, it may also be disposed in a casing, a production tubing, or the wellbore wall for measuring pressures in the wellbore. Furthermore, a flow rate measuring device 23 is shown to be disposed in the wellbore 20. Note that the flow rate measurements may also be performed on the surface, i.e., the flow rate measuring device 23 may be deployed on the surface in accordance with some embodiments of the invention.

In accordance with some embodiments of the invention, the flow rates in the wellbore 20 may be varied (e.g., by changing the pump rates), and the flow rate changes may be measured by using the device 23. The pressure changes in response to such flow rate changes may be recorded or detected in the wellbore using the sensor 21 and in the formation using sensor 22.

For example, the production rate may be increased to create a transiently lower pressure in the wellbore 20, similar to performing a drawdown. In response to the lower pressure transient, the fluid flow from the formation will increase until a new steady state is reached. Alternatively, the pump may be shut off after the pressure perturbation to create a shut-in. During the shut-in period, the pressure will gradually buildup in the wellbore when the fluids from the formation flow into the wellbore. The pressure changes in the wellbore (sensor 21) and the formation (sensor 22) may be monitored during the drawdown and buildup periods for later analysis. Note that the flow rate (or pressure) changes may also be achieved with other methods, e.g., by a flow or pressure pulse.

The pressure measurements recorded by each sensor may be analyzed separately as in a conventional approach. Such analysis typically involves the use of a plot in a form of pressures versus the log of shut-in time. Such a curve is conventionally referred to as a Homer Curve. In addition, a Homer curve may be analyzed as a derivative with respect to time, which produces a Bourdet Curve. In a radially extending reservoir without boundaries, the Homer curve exhibits a gradual increase of the pressure until the pressure reaches that of the formation pressure. In the Bourdet curve, the rates of pressure changes will gradually decrease to approach zero when the buildup is complete.

In accordance with some embodiments of the invention, the measurements recorded by the sensor in the wellbore (sensor 21) and in the formation (sensor 22) may be analyzed together. For example, the pressures (or the rate of pressure changes) detected by these two sensors may be compared, either as ratios or as differences.

FIG. 3 shows one example, in which the pressures (or pressure changes) measured by the sensor in the wellbore (sensor 21) and in the formation (sensor 22) are analyzed as differences. As shown in FIG. 3, there is a significant difference at the beginning of the monitoring period, i.e., right after the perturbation created by flow rate changes. This difference eventually settles down to a steady state value as the pressures in the system eventually reach an equilibrium, illustrated as the baseline 31. The spikes up and down 32 are from transient changes in the flow, e.g., due to pump stoppage or gassing out in the fluids. The steady-state value, represented by the baseline 31 in FIG. 3, relates to the hydraulic resistance in the near wellbore region. Accordingly, this values may be used as a near wellbore production index (NWPI). The NWPI is a good indicator of how well the near wellbore region perform under the production conditions because the far-field effects are removed in the difference.

The near wellbore production index (NWPI) is different from the conventional production index because the conventional production index measures how the well performs as a unit, i.e., there is no distinction between the near wellbore, matrix, and far-field effects. Conventional production index is typically expressed as the volume delivered per psi of drawdown at the surface (bbl/psi). The NWPI is useful because it can inform the operator that slow production may be due to problems in the near wellbore region. In that case, remedial measures may be taken to improve the well performance.

Note that while FIG. 3 shows difference in the measurements made with the sensors in the wellbore and in the formation, one of ordinary skill in the art would appreciate that one may also analyze the measurements as ratios. Such ratios will also reflect near wellbore effects because the far-field effects (which is minimally perturbed by the flow rate changes in the wellbore) is factored out in the ratios. Thus, the near wellbore production index (NWPI) may also be based on ratios.

The system shown in FIG. 3 uses two sensors. This may be referred to as a two-node system. Embodiments of the invention may use two or more nodes (sensors). With more nodes, more sophisticated analysis becomes possible.

For example, FIG. 4 shows a three-node system in accordance with one embodiment of the invention. In this particular example, sensor 41 is disposed in the wellbore 40, while sensors 42 and 43 are disposed in the formation (e.g., production zone 10 a) such that they are in different radial directions from the wellbore, i.e., sensors 42 and 43 are disposed at different azimuthal angles (locations). In this particular example, sensors 42 and 43 are separated by about 180° in azimuthal angles. However, in accordance with some embodiments of the invention, these sensors may be separated with azimuthal angles other than 180°. Furthermore, in accordance with some embodiments of the invention, more sensors (more than 3 nodes) may be used and are disposed at various azimuthal angles and/or different radial distances. In accordance with embodiments of the invention, the sensors in the formation (e.g., sensors 42 and 43) may be disposed at the same or different radial distances from the wellbore. With such a set up, it is possible to assess separate near-wellbore effects at different locations (i.e., different azimuthal angles), by analyzing measurements in pairs (e.g., sensors 42 and 41 as a pair, or sensors 43 and 41 as a pair) as described above with reference to FIG. 3.

In addition, measurements obtained with such a multi-node system may be analyzed to derive the far-field effects, e.g., reservoir boundaries. Thus, in accordance with some embodiments of the invention, multiple nodes may be used to detect orientation and relative distance of reservoir boundaries to the wellbore. One exemplary approach is illustrated in FIG. 5 and FIG. 6.

FIG. 5 shows an illustrative set up with a three-node system, similar to that shown in FIG. 4. In addition, a near reservoir boundary 58 (about 1,500 ft or 500 m from the well) and a far reservoir boundary 59 (about 3,000 ft or 1,000 m from the well) are shown to be present in that zone. In this particular example, sensor 51 is disposed in the wellbore at about 0.2 ft (6 cm) from the center of the well, while sensors 52 and 53 are disposed about 12 ft (4 m) into the formation from the well. Sensor 52 is closer to the near reservoir boundary 58, while sensor 53 is closer to the far reservoir boundary 59. Note that the illustration in FIG. 5 is not to the scale. Furthermore, one of ordinary skill in the art would appreciate that the particular dimensions and configuration are for illustration only and are not intended to limit the scope of the invention.

Using the three sensors shown in FIG. 5, the three sets of measurements obtained by the three sensors 51, 52, 53 may be analyzed separately, as shown in FIG. 6. The curves shown in FIG. 6 are Homer curves (61H, 62H, 63H) and Bourdet curves (the derivatives of Homer curves) (61B, 62B, 63B) for the three sensors 51, 52, 53, respectively.

As shown in FIG. 6, the Homer curves 61H, 62H, 63H show the typical gradual increase in the pressures. It is relatively difficult to discern any pressure changes, besides the typical buildup, from these Homer curves. On the other hand, the Bourdet curves can reveal more details about the pressure changes that may result from far-field effects, e.g., reservoir boundaries.

Referring to the Bourdet curves 61B, 62B, 63B, there is a significant difference between curve 61B and those of 62B, 63B during the initial time period (e.g., up to 0.1 hr). This is because the drawdown lowers the pressure inside the wellbore substantially more than in the formation. All three curves eventually merge in the middle time period (about 0.1 to 10 hours), indicating that the buildup is approaching completion and the system is reaching a steady state. In the later time period (greater than 10 hours), perturbations to the steady state is apparent. These perturbations indicate late events that originate from far fields have been detected by the sensors.

As shown in the expanded inset, all three curves 61B, 62B, 63B show a dip 68 during this late time period. This dip results from the impact of the near reservoir boundary 58. Although the fluid “waves” arising from the effects of the near boundary 58 are felt almost simultaneously by all three sensors, careful analysis reveals that the curve 62B (corresponding to sensor 52, which is closer to the near boundary 58) starts to decrease before other curves 61B and 63B. Curve 62B also starts to recover before the other two curves. This observation indicates that the near boundary 58 is closer to sensor 52 than to sensor 53.

After the first dip 58, all three curves 61B, 62B, 63B show another dip when the impact of the far boundary 59 is felt by the three sensors. This time, curve 63B (corresponding to sensor 53, which is closer to the far boundary 59) starts to dip first. Curve 61B (corresponding to the sensor 51 in the wellbore) dips next, followed by curve 62B (corresponding to sensor 52). These results indicate that the far boundary effects are first felt by sensor 53, and, therefore, the far boundary 59 is closer to sensor 53 than to sensor 52.

The above example clearly shows how a three-node system can be used to detect the relative locations and distances of reservoir boundaries in accordance with embodiments of the invention. As noted above, embodiments of the invention may include more then three nodes. Such systems may be used to further pinpoint the orientations and distances of the boundaries.

In addition to the “qualitative” analysis illustrated above, the data may also be analyzed for quantitative information. For example, the relative arrival times (to the sensors) is a function of the distances from the boundaries to the sensors. Because the pressure waves disperse out in “spheres,” it takes four times longer for the waves to travel twice the distance, i.e., the distance correlates with square root of time (d correlates with t^(1/2)). Thus, if it takes four times longer for the far boundary to reach the sensors than does the near boundary, then it can be concluded that the far boundary is about twice farther, as compared with the near boundary, from the sensors. For detailed analysis, please see U.S. Pat. No. 5,548,563 issued to Slevinsky.

Note that while the analysis shown in FIG. 6 uses the Homer and Bourdet curves. In accordance with some embodiments of the invention, these data may also be analyzed as differences (as illustrated above in reference to FIG. 3) or ratios. For example, in the above example, the measurement data from sensors 52 and 53 may be used to derive the differences and/or ratios, which may then be used to determine the orientations and relative distances of the boundaries. In particular, ratios may provide a more sensitive indicators as to the relative orientations of the boundaries.

Embodiments of the invention may use any suitable pressure sensors known in the art. For example, U.S. Pat. No. 7,140,434, issued to Chouzenoux et al., discloses sensors for installation in an underground well having a casing or tubing installed therein. This patent is incorporated by reference in its entirety. A sensor, as disclosed in this patent, comprises a sensor body, sensor elements, and communication elements. The sensor body can be installed in a hole formed in the casing or tubing so as to extend between the inside and outside of the casing or tubing, while the sensor elements are located within the body and capable of sensing properties of an underground formation surrounding the well. The communication elements are also located within the body and capable of communicating information between the sensor elements and a communication device in the well.

These sensors may be deployed in the wellbore, casing, and formations using any suitable methods known in the art. For example, U.S. Patent Application Pub. No. 20050217848, by Edwards et al., discloses methods of installing a sensor located in a chamber on the outside of a casing. This application is incorporated by reference in its entirety.

Furthermore, U.S. Pat. Nos. 6,028,534 and 6,943,697 issued to Ciglenec et al. disclose methods for installing sensors in the formation. According to the teaching in these patents, remote sensing units may be set during open-hole operations. Alternatively, the remote sensing units may be deployed from a drill string tool that forms part of the collars of the drill string, similar to that disclosed in the Edwards et al. described above. In another approach, the remote sensing units may be deployed from an open-hole logging tool.

The sensors or sensing units can be positioned within the formation of interest by any suitable means, as disclosed in U.S. Pat. No. 6,028,534 issued to Ciglenec et al. For example, a hydraulically energized ram can propel the sensor from the drill collar into the formation with sufficient hydraulic force for the sensor to penetrate the formation by a sufficient depth for sensing formation data. Alternatively, apparatus in the drill collar can be extended to drill outwardly or laterally into the formation, with the sensor then being positioned within the lateral bore by a sensor actuator. As a further alternative, a propellant energized system onboard the drill collar can be activated to fire the sensor with sufficient force to penetrate into the formation laterally beyond the wellbore. The sensor is appropriately encapsulated to withstand damage during its lateral installation into the formation, whatever the formation positioning method may be.

FIG. 7 illustrates a method 70 in accordance with one embodiment of the invention. First, a pressure perturbation is created in a wellbore (step 72). As noted above, such pressure perturbations may be created by varying the pump rates. Next, with a selected duration while the buildup is occurring, the pressures or pressure changes in the wellbore and in the formations are recorded (step 74). The measurement data, both from the wellbore and from the formation, are then analyzed, as described above, to provide a formation property (e.g., near wellbore production index, reservoir boundaries, etc) (step 76).

Advantages of the present invention may include one or more of the following. Embodiments of the invention provide methods that can be used to probe formation properties with respect to the near wellbore effects and far field effects. The methods of the invention may also be used to detect the reservoir boundaries in terms of the relative distance and orientations. These methods may be practiced with any suitable sensors and techniques known in the art.

While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised that do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims. 

1. A method for measuring formation property, comprising: obtaining a set of measurements indicative of wellbore pressures for a selected duration after a pressure perturbation is created in a wellbore; obtaining at least one additional set of measurements indicative of formation pressures for the selected duration after the pressure perturbation; and deriving the formation property based on the set of measurements indicative of the wellbore pressures and the at least one additional set of measurements indicative of formation pressures.
 2. The method of claim 1, wherein the deriving comprises calculating differences or ratios between the first set of measurements and the at least one additional set of measurements.
 3. The method of claim 1, wherein the formation property relates to a near wellbore hydraulic resistance.
 4. The method of claim 1, wherein the formation property is a far field formation property.
 5. The method of claim 4, wherein the far-field formation property relates to a reservoir boundary.
 6. The method of claim 1, wherein the deriving involves using a Homer curve or a Bourdet curve.
 7. A system for measuring formation property, comprising: a first pressure sensor disposed proximate a wellbore for measuring pressures in the wellbore; a second pressure sensor disposed in a formation at a predetermined distance from the wellbore; and a flow rate measuring device.
 8. The system of claim 7, further comprising a third pressure sensor disposed in the formation in the same zone as the second pressure sensor, but at a location different from that of the second pressure sensor.
 9. The system of claim 8, wherein the second pressure sensor and the third pressure sensor are disposed at azimuthally different locations relative to the wellbore.
 10. The system of claim 9, wherein the second pressure sensor and the third pressure sensor have an azimuthal angle separation of about 180 degrees relative to the wellbore. 